Produced hydrocarbons, and in particular heavy hydrocarbons such as bitumen, are often subjected to one or more upgrading processes between the stages of field production and commercial product. This is because various produced hydrocarbons often have one or more undesirable properties which interfere with their transportation and/or use as a feedstock in various refining processes. For example, produced hydrocarbons can be acidic (i.e. have high TAN (total acid number)), which can cause damage to production, transport, and processing equipment and interfere. Produced hydrocarbons such as bitumen can also be viscous, dense, or have a relatively low API (American Petroleum Institute) gravity, which can prevent or complicate transportation and processing operations. Produced hydrocarbons can also contain sulfur (e.g., in the form of H2S or mercaptans), for which produced hydrocarbons often need to be treated to meet regulatory emissions or waste disposal requirements and pipeline specifications for oil transportation. As such, processing steps to reduce TAN, viscosity, density or sulfur content each represent common upgrading processes in the oil industry. Produced hydrocarbons having reduced TAN, reduced viscosity, reduced density, reduced sulfur content, or any combination thereof, may be considered as being upgraded or partially upgraded, and thus may be a more valuable product as compared to the raw produced hydrocarbon recovered from the reservoir.
Corrosion of metal components derived from organic acids present in produced hydrocarbon streams is an undesirable phenomenon initially studied in relation to lubricants and the effects of organic acids on metal surfaces [1-3]. Detailed studies have been carried out regarding aircraft engines, and the dramatic effect that metal failures can pose in these areas [4]. Acidity is routinely determined by titration of acidic components with KOH, following standard procedures for TAN (Total Acid Number) [5] determination. Petroleum, particularly heavy oil and bitumen, can have substantial amounts of acidic compounds [6]. Typical acidic species present in oils in varying proportions are carboxylic acids, phenols, mercaptans and sulfones.
The main acidic species found in some heavy/extra-heavy oil distillation cuts belong to the carboxylic acid (about 50-60% wt) and phenolic (about 10-20% wt) families [8]. It is widely accepted that oils or derived fractions having TAN higher than about 0.5 mg KOH/g sample are “Acidic”, and may be prone to cause corrosion problems on steel facilities [7], and could contain a high concentration of naphthenic acids (NA) that can adversely impact the reliability and operations of refineries. Commonly reported problems may include corrosion, desalter glitches, fouling, catalyst poisoning, product degradation, and/or environmental discharge, among others. For this reason, crudes with high TAN (greater than about 1 mg KOH/g sample, which is typically characterized as an acidic crude) would be subject to a discount. However, a clear correlation between TAN, corrosivity, and carboxylic acids has proven elusive, probably because the acidic molecules in each oil may vary as a result of its origin, geochemical maturation pathway, and other phenomena like bacterial degradation, air/water oxidation, and artifacts derived from production operations [7, 8]. Findings suggest that the whole acidic fractions contain most of the corrosive potential [9]. A complex filling/biodegradation history may be responsible for such high TAN numbers in bitumen [9].
Naphthenic corrosion may be particularly important around the boiling temperature of acidic compounds responsible for the phenomenon. These compounds normally maximize their concentration in the Vacuum Gas Oil (VGO) range, but their distribution can vary from oil to oil. FIGS. 1(A) and 1(B) present the evolution of TAN with the fraction's boiling range, along with other properties for two different samples of South American heavy oils. The results show the previously discussed TAN concentration around gas oil distillation fractions.
Various methods have been employed for reducing TAN and may include, for example, caustic washing to remove naphthenic acids in gasoline and kerosene. However, this approach can fail when applied to heavier feedstocks with high TAN due to the formation of very stable emulsions. An approach by refineries involves reacting acid content with alcohols to reduce TAN; however, this process is reversible, which can diminish its effectiveness once the oil is further treated/refined. Acids can be destroyed by thermal treatment or cracking to generate carbon dioxide gas and low acid hydrocarbon content, however, some undesirable side reactions can occur resulting in the formation of sediments and gums that negatively impact the value of the crude. Adsorption on solid surfaces and the use of solvent extraction can also be approaches to extracting naphthenic acids from oil; however, losses in profits due to overall volume reduction can make such processes unattractive. Generally, treatments and processes for reducing high acid content in produced hydrocarbons add time and expense to transportation and refining operations.
Totally eliminating the acidity present in a crude oil is generally considered difficult and expensive. Due to the fact that TAN distribution is usually centered in the VGO fraction, fractionation of the heavy oil to separately treat the more acidic stream may require cutting the heavy atmospheric gas oil, and all the vacuum gas oil (about 280-540° C.). If the target were to reach a TAN lower than about 1 mg KOH/g oil, an average TAN reduction of the processed fraction higher than about 80% may be needed in this case. For most heavy oils, this would imply treating about 40% of the oil. Considering the properties distributions, the heavy oil fractioning to separately treat the more acidic stream would require cutting the ˜250° C.+ Heavy atmospheric gas oil and all the VGO.
For a medium crude oil, the same TAN reduction target for the whole oil would imply cutting the entire ˜220° C.+ fraction, and treating practically the whole oil (about 90% of it), with TAN reduction levels of about 65%, and thus, lower severity.
The reduction of TAN for acidic crude oils has been studied based either on acid removal through adsorption over solid sorbents or via their catalytic enhanced decomposition, most typically via hydroprocessing [11]. Supported catalysts containing Ba, Sr, Cu, Ag and Ni active metals were described for the decarboxylation reaction of small compounds (i.e., 6-7 carbon atoms) containing naphthenic/aromatic acids, with noticeable conversions reported in some cases up to 98% (as evolved CO2) (see FIG. 1) [11].
Furthermore, acids removal over metal salts (Na and K carbonates and Na borate) have been reported, however using large amounts (20 wt %) of these solids [12], which is deemed suitable for academic purposes but not for industrial applications. An industrial solid, spent FCC catalyst, has been also proposed for TAN reduction, also in a large relative ratio of solid/sample=5/1 [13A]. TAN reduction using solid adsorbent has been carried out using MgO and CaO; however, determined reduction levels have been considered low (i.e. about 23% TAN reduction in 30 minutes at 360° C. and 361 bar, unpublished results) the apparent reason being competition for the adsorption sites from heavier molecules. Reaction under the effect of hydrogen transfer compounds already described in the patent literature [14A] has been considered as another plausible alternative for getting rid of acidic components from hydrocarbon streams however this path would not escape from deactivation and competition from heavy molecules present in the feedstock which would eventually reduce the TAN benefits and deactivate the catalytic sites.
Separating the acidic fraction can be performed in two steps for example via an old process used in Shell Oil Company refineries [15A]. This process consists on spreading a solution of NaOH inside a vacuum distillation column to form organic salts with surfactant capabilities (emulsification), which allows separating the heavier emulsion fraction inside online electrostatic tanks, from which the naphthenic acids are latter obtained and purified by treatment with concentrated sulfuric acid. This process would require, in addition to the investment in a vacuum distillation unit, massive handling of dangerous chemicals, further used water treatment and the disposition of a naphthenic acid stream of extremely high TAN (typically >25 mgKOH/g oil). This process has been discontinued from refineries since late last century due to operating difficulties caused by inverse emulsions and environmental issues.
As noted above, achieving TAN reduction in produced hydrocarbons, such as full Athabasca bitumen, with reduced, lowered and/or minimal investment in facilities on site has been difficult. Avoiding, reducing or minimizing processes that involve separation by distillation [10] are of interest, due to the high investment costs, high capital expenditures, and increased complexity these operations may imply for field operation. TAN reduction using solid adsorbent has been carried out using MgO and CaO; however, determined reduction levels have been considered low (i.e., about 23% TAN reduction in 30 minutes at 360° C. and 361 bar), using a commercially developed MgO adsorbent with one apparent reason being competition for the adsorption sites from heavier molecules.
Reaction under the effect of hydrogen transfer compounds already described in the patent literature [13] has been considered as another plausible alternative for getting rid of acidic components from hydrocarbon streams, but this path would not escape from deactivation and competition from heavy molecules present in the feedstock which would eventually reduce the TAN benefits and deactivate the catalytic sites.
Applying more selective chemical paths in the absence of heavier components (i.e. adsorption, catalysis, electrochemistry) might be an option as well; however this would also involve distillation to separate the acid rich lumped fraction. Some other hydroprocessing schemes involve the use of conventional hydrotreatment of the whole crude oil to reduce TAN [10].
Currently, totally eliminating the acidity present in a crude oil is difficult and expensive. When considering the TAN distribution in FIGS. 2(A) and 2(B), the heavy oil fractioning to treat (separately) the more acidic stream would require cutting almost the whole 343° C.+ fraction, which includes light gas oil (LGO) and the atmospheric residue. If the target were to reach a TAN lower than 1 mg KOH/g oil, an average TAN reduction of the processed fraction of higher than 80% would be needed. For this bitumen, it would imply treating 86% of the oil (9 vol % LGO+76.95 vol % atmospheric residue). Another case could be to distill the whole crude, and process only those fractions with TAN higher than 1 mg KOH/g oil. In this case LGO, heavy gas oil (HGO), and VGO would have to be treated. This would imply treating about 42% of the oil, and a larger investment due to fractionation of the bitumen, to obtain vacuum fractions (See FIG. 2(B)). These examples illustrate the relevance of the information in FIGS. 2(A) and 2(B) for acidity reduction hydroprocessing and present the evolution of TAN with the fraction's boiling range for a sample of crude oil.
TAN Determination
As previously mentioned, naphthenic corrosion is particularly important around the boiling temperature of acidic compounds responsible for the phenomenon. These compounds normally maximize their concentration in the Vacuum Gas Oil (VGO) range, but their distribution can vary from oil to oil.
TAN determination is currently carried out via standard ASTM D664 method [16]. Accuracy determined with known samples is reasonable for a TAN spanning the 1-4 range (FIG. 3). Fortunately, most samples of interest show TAN values comprised within this range. Outside of these limits, accuracy becomes an issue.
Repeatability is another issue implicit with the analysis methodology. Analysis of feedstocks and products carried out during the same session (same day), was found to overcome the problem as shown by a TAN mimic reduction simulated by dilution with an inert base oil. This suggests that great care should be taken when comparing TAN results for wide sets of samples, especially those analyzed during long periods of time, particularly those arising from different laboratories.
Other issues around acidic hydrocarbons and/or benefits of effective TAN reduction can include:
Processes that involve NA separation by distillation [10] are typically associated with high investment costs and increased complexity for field operation.
Extracted bitumen and heavy oils may require transportation to a geographically distant refinery or processing plant. Such transport may be done through a pipeline. Unfortunately, the relatively high viscosity of these produced hydrocarbons can make pipeline transport difficult. Transportation via pipeline requires that the hydrocarbons being transported meet specific requirements, such as the API (American Petroleum Institute) gravity and viscosity requirements. Extracted hydrocarbons, such as bitumen, typically do not meet the transportation specifications due to high viscosity, and as such are typically further processed, upgraded, or diluted prior to pipeline transportation.
The processing of the extracted hydrocarbons to meet the specific transportation specifications commonly involves mixing the extracted hydrocarbons with a diluent. The diluent may include natural gas condensate, refined naphtha or synthetic crude oil (SCO). The diluent either needs to be produced on site, which may require expensive processing equipment, or must be produced elsewhere and transported to site. The cost of diluent is added to the cost of extracting and transporting the hydrocarbons.
As noted, produced hydrocarbons may have a TAN number as high as about 10-12 mg KOH/g sample in some parts of the world. For transport and refinement, it is generally desirable to have a TAN less than about 1 mg KOH/g sample. In North America, TAN of about 1.5-3 mg KOH/g sample is common in produced hydrocarbons. A TAN greater than about 1 mg KOH/g sample can reduce the value of produced hydrocarbons and complicate transportation of the produced hydrocarbons to a refining facility.
Accordingly, it desirable for a crude oil to have a low TAN number in order to meet the requirements of various refineries. As a general guideline those skilled in the art would understand that an “acid crude oil” would typically be one with about a TAN >0.5 mg KOH/g, while a “High TAN crude” would typically be one with a TAN >1.0 mg KOH/g. Thus it is desirable for a crude oil to have a TAN of <1.0 mg KOH/g, and even more desirable to have a TAN of <0.5 mg KOH/g.
Further still, produced hydrocarbons, such as bitumen and heavy oils, such as those found in Alberta, Canada, and elsewhere, may be viscous mixtures of saturated and aromatic hydrocarbons and other naturally occurring components including paraffins, naphthenes, resins-asphaltenes with variable distributions of heteroatoms such as sulphur, oxygen and nitrogen in hydrocarbon compounds as well as metal-organic compounds. Many of these hetero-compounds have an important role in the molecular cross-linking that naturally increases the viscosity of bitumen and heavy oils. This is due to polar interactions between sulphur and oxygen compounds, usually with acidic character, with nitrogen and poly-aromatic compounds with more of a basic character. By reducing or eliminating at least one of the polar families of compounds present in the oil the molecular cross-linking can be substantially reduced. Therefore, the reduction of TAN has a double benefit for the heavy hydrocarbons production industry, on one hand the impact on corrosion downstream of the production activity (upgrading and refining) is sensibly reduced, which reflects positively in the price of the oil but also reducing TAN will reduce viscosity which impacts positively in the reduction of diluent needs for transportation of heavy hydrocarbons to the refining centers.
Accordingly, a need exists for additional, alternative, and/or improved processes for upgrading, or partially upgrading, produced hydrocarbons such as whole crude oil, or bitumen.
In addition, there has been a need for new catalytic materials that are effective in treating heavy oils for TAN reduction. More specifically, there has been need for catalytic materials having both compositional and morphological properties that make them effective for TAN reduction.
Further still, upgrading of hydrocarbon feedstocks can be accomplished by hydrogenation and cracking of large organic molecules contained in the original feedstock with the help of a high partial pressure of hydrogen and temperatures. This process is generally known as hydrocracking. The use of hydrogen at high pressure not only increases the cost of the required equipment but also, impose strict safety policies. If the source of hydrogen could be provided from another source, like water, some of the economics and safety issues relating to hydrogen use could be avoided. However, innovation in the development of catalysts that can extract the hydrogen from the water and use it for in situ upgrading of hydrocarbon feedstocks must be accomplished.
Conventional steam cracking is an uncatalyzed cracking process used in the petrochemical industry to break down hydrocarbons increasing the yield of olefins. This process works at atmospheric pressure and requires very high temperatures to induce the thermal cracking of the gaseous hydrocarbons. However, in this process, steam is added to the mixture of gaseous hydrocarbons to lower the partial pressure of the hydrocarbons to a point at which polymerization and condensation reactions of the produced olefins are reduced. In this case, the steam acts as a diluent of the gaseous hydrocarbons and inhibits carbonization (coke formation) but does not supply hydrogen to the products.
Reference [1B] shows a process, patented by Phillips Petroleum Co, for upgrading crude oils in which relates to the in situ generation of hydrogen in contact with a hydrocarbon to thereby produce materials of low molecular weight and of reduced carbon residue and sulfur content. In the process, water is introduced with the hydrocarbon feedstock together with a catalyst system containing at least two components where one of the components promotes the generation of hydrogen from water and the other component promotes reactions between the generated hydrogen and hydrocarbons in the feedstock to produce an upgraded hydrocarbon from which liquid products of reduced molecular weight, carbon residue and sulfur content can be separated. The production of hydrogen in the presence of water and the crude oil is by means of a water gas shift reaction. The first component of the catalyst system are carboxylic acid salts of barium, calcium, strontium and magnesium which are soluble in the crude oil in the quantities employed. The second component of the catalyst system are carboxylic salts of nickel, cobalt and iron which are soluble in the crude oil to the extent to which they are added thereto.
Generally, in this process there is no catalytic bed and the water to crude oil volumetric ratio is preferably between 0.2 to about 2.5. The preferred pressure and temperature for the process is 500 to 2500 psig and 790 to 835° F., respectively.
From the above, there has also been a need for the use of the material compositions that are effective in processes of steam catalytic cracking for the upgrading of hydrocarbon feedstocks.